In the oil and gas industry, the output of a production well is usually a multiphase mixture of oil, water, and gas, commonly referred to as three-phase flow. The gas itself can be present in two forms: as free gas in the form of bubbles or slugs, or as dissolved gas tightly bound to the liquid. The relative proportions of free and dissolved gas vary with many factors, most notably pressure. Thus, for the same well production stream with constant mass flow rates of oil, water and gas, the proportion of gas coming out of solution to become free gas will increase as the line pressure decreases downstream. Accurate assessment of the output of each well is important for reservoir management, as well as for the payment of royalties and taxation.
The output of each petroleum well could be measured on a continuous basis with a dedicated metering system capable of monitoring the three phase simultaneously. Such a device is known as a three-phase flow meter. Unfortunately, it is at present uneconomic to meter wells individually using dedicated three-phase flow meters. As discussed below, the most widely used system for measuring three-phase flow is the separator, which physically separates at least the gas and the liquid. In many separator systems the oil and water are also separated. Separator systems are large and expensive, and it is uneconomic to provide a separator for each well. Instead, the industry has developed the practice of using well test stations, where the outputs of many wells are brought together to share a single multiphase measurement system, i.e. a test separator.
Referring to FIG. 1, a conventional well test separator selects 1 of N wells (where N is typically 6-60) and directs the multiphase flow from a well that has been selected for testing into a separator system so that the well output can be tested or measured. The outputs from all the unselected wells are typically pooled and sent unmeasured to the production facility, bypassing the test separator. Once the testing of the selected well is complete, a different well can be selected for testing. Thus, all N wells can eventually be tested one at a time using the conventional test separator.
FIG. 2 shows a conventional separator system in more detail. The multiphase flow is directed into a separator vessel, which has sufficient capacity to enable the gravimetric separation of at least the liquid (e.g., oil and water) from the gas. Other separator designs have additional features to enable the further separation of the oil from the water. The separated gas rises, and is piped away on the “gas leg” to be metered by a suitable gas flow measurement device, such as a vortex meter or a Coriolis mass flow meter. Similarly, the liquids are piped away on the “liquid leg” to be metered by a suitable liquid flow measurement device, such as a positive displacement meter, a vortex meter, or a Coriolis mass flow meter. Further measurements can be taken to determine the ‘water cut’, or proportion by volume of water within the liquid mixture, so that the individual oil and water flow rates can be calculated. For example, a water cut meter can be incorporated into the liquid leg. Alternatively, if a Coriolis meter is used to meter the liquid, its density reading can be used to determine the water cut.
A range of techniques, familiar to those skilled in the art, may be used to manage the separation and measurement of the liquid and gas streams by conventional separator systems. Typically, level and/or pressure control is used. For example, the level of the liquid in the separator may be maintained between an upper and lower limit, or the pressure at the top of the separator may be maintained between an upper and lower pressure limit, or some combination of the two may be implemented. Flow out of the separator through the liquid and/or gas legs may occur continuously or in batches, depending upon the control scheme implemented. In any event, phase separation entails gravimetric separation of the various constituents of the multiphase flow, which requires the separator tank or vessel to be large enough to provide a suitable setting time for allowing gravimetric separation of the fluids. Because of the settling time in the separator vessel, there is no way to correlate instantaneous gas or liquid flow rate measurements with any instantaneous flow rates into the separator vessel. In other words, there is no way to correlate the instantaneous oil, water and gas flow rates of the well being tested with the instantaneous flow outputs from the separator.
For example, FIG. 3 shows the observed flow pattern from a conventional separator as it monitors an oil and gas well over a two hour test period. The upper plot shows the flow measurement reported on the liquid leg, in tons per day (t/d), while the lower graph shows the reported flow measurement on the gas leg, in standard cubic meters per day. In this example, the separator control scheme operates so that liquid normally flows through the liquid leg meter, but from time to time (for example when the pressure in the separator reaches an upper limit) a gas purge takes place, where the liquid leg is shut off and the gas leg is opened up to expel gas from the separator and meter the gas. Each gas purge is characterized by an initial spike in gas flowrate, followed by a sharp decline and then a more gradual decline. When the separator pressure drops to its lower limit, the gas leg is closed and the liquid leg is reopened.
Over a sufficiently long period the flow entering the separator must equal the flow leaving the separator. However, the original flow behavior from the well is largely destroyed by the separation process. The pattern of flow exiting the separator and recorded by the gas and liquid meters is mostly determined by the separator control scheme, not the pattern of flow entering the separator. For example, it is likely that the gas flow rate from the well is more continuous than the pattern of gas purges observed in the gas leg. Thus, no real-time information on the pattern of well flow is provided by this conventional separator system. Typically, therefore, for each well test, only the totalized flows of gas and liquid (sometimes further distinguished as oil and water) are reported, along with the totalized time. Thus, a separator can be used to determine average flow rates for each of the phases, but not the dynamic flow behavior.
A further limitation of separators, which follows from this interrupted pattern of flow, is that a long testing period is often necessary to ensure accurate measurements. For example, in FIG. 3, the time delay between gas purges is up to 50 minutes. If the test had been completed immediately before the final gas purge, say at 11:30, the average gas flow rate reported would have been quite different. Thus, given that the gas and/or liquid streams may leave the separator in a series of cycles, it is important to ensure the test period is long enough to have sufficient separator cycles so that incomplete cycles at the beginning or end of the test period do not introduce significant errors. When switching between wells that are being tested, it also is important to set aside sufficient time to flush the separator through completely with the new well stream before starting a new test or additional measurement errors will be introduced. These issues limit the ability to test wells quickly.
FIG. 4 illustrates another problem that can occur when using a conventional test separator. If gas/liquid separation is incomplete (e.g., if an emulsion is formed, or if the separator is undersized for the well flow rate), then gas carry under and/or liquid carry over may take place. Gas carry under occurs when gas leaves the separator through the liquid leg. Liquid carry over occurs when liquid leaves the separator through the gas leg. FIG. 4 shows liquid carry-over occurring at the very start of a test period, in data collected from the same separator with the same control schemes as shown in FIG. 3. The top graph shows the liquid flow rate leaving the separator, which is essentially steady other than the regular drops in flow when the liquid leg is closed for gas purges. The middle graph shows the gas flow rate reading from a Coriolis mass flow rate meter on the gas leg. There are regular bursts of gas flow coinciding with each of the pauses in liquid flow, as expected, but the graph is dominated by the first burst of gas occurring at time 16:25. The bottom graph shows the density reading from the Coriolis meter on the gas leg. The density time series demonstrates that for much of the test the density is around 30 kg/m3, which is the expected value for the gas composition and the operational pressure. However, at the initial purge of gas at time 16:25, the density rises to above 400 kg/m3. This can only have been caused by liquid carry-over, where liquid is carried through into the gas leg, resulting in a very high density reading from the Coriolis meter on the gas leg. In this case the liquid carry over appears to cause a large over-reading of the gas mass flow before the end of the liquid carry over event. Similarly, in the case of gas carry under, when gas/liquid separation is incomplete it is possible for some gas to be passed through the liquid leg, which may introduce errors in the liquid flow meter. Gas carry under in the liquid leg can be detected by density readings from the liquid leg that are too low.
A related potential problem with the conventional separator arrangement in FIG. 2 concerns the effects of dissolved gas. As is well known to those familiar with the industry, natural gas readily dissolves in oil. The amount of gas dissolving in the oil is a function of several parameters, including temperature and pressure. Specifically, at higher pressures more gas can be dissolved into a given volume of oil. Accordingly, at each stage of the upstream oil and gas production process, whenever the pressure decreases, some gas will be released from solution in the oil. Thus, even when there is no gas carry under, the pressure drop across the liquid meter will induce a proportion of gas to come out of solution, and in that sense the fluid measured in the liquid leg is not purely liquid because of the gas therein. Even small amounts of gas coming out of solution can cause significant measurement errors in some conventional liquid phase meters, for example some conventional Coriolis meters.
Moreover, each separator is typically used to test the outputs from many wells, and so must be designed to deal with the range of flow conditions across all these wells, as characterized by liquid volumetric flowrate, water cut, GVF, pressure and other parameters. Choosing the most appropriate capacity for a separator, given the set of wells to be tested, is a matter of balancing different considerations. It is desirable to minimize the separator size in order to keep the cost of construction as low as possible. However, if the capacity of the separator is too small for high flowing wells, the separation process may be incomplete, leading to liquid carry over and/or gas carry under with the likelihood of measurement errors induced in the gas and liquid leg flow meters. On the other hand, if the capacity of the separator is too large, then for low flowing wells the test period may need to be significantly extended to ensure sufficient separator gas purge cycles for the desired measurement accuracy. In practice, a single separator can be used in the industry to measure a well cluster with a wide range of well flow rates—for example a ratio of 20:1—between the highest and lowest liquid flow rate. However, the need to accommodate a wide range of flow rates does limit the options available for well testing.
The present inventor has developed systems and methods that improve on the conventional systems described above and which will be described in detail below.